Abrasive perforating, which is an alternative to explosive charge perforating, is a common procedure in the oil and gas business used to create a communication path from a wellbore to a reservoir. The communication path is created by pumping fluid, normally containing an abrasive medium, through specialized jetting nozzles at high pressure. The fluid, when ejected from the jetting nozzles, erodes through the casing, cement and into the formation. Abrasive perforating can be performed using conventional tubing, but is more commonly carried out using coiled tubing (CT).
In many cases abrasive perforating is combined with a stimulation treatment using sand plugs or mechanical plugs for zonal isolation between the sets of perforations to allow each zone to be stimulated individually, if required, before creation of the next set of perforations.
Originally the procedure was conducted on vertical wells using a bottom hole assembly (BHA) containing a reverse ball check valve. Such a BHA is shown in FIG. 1 in an illustrative configuration, which, as with all BHAs in this application, may change based on well conditions and other variables. The BHA components may include a CT connector 10, a disconnect 20, a stabilizer 30, an abrasive cutting sub 40 with at least one jetting nozzle 50, another stabilizer 60, a reverse ball check valve 70 containing a pin 80 and ball 90, and finally a nozzle 100.
In this setup, when pumping fluid down the CT, the reverse ball check valve 70 is forced closed, preventing the fluid from exiting the nozzle 100 below (at the bottom of the BHA) and directing the fluid through the jetting nozzle(s) 50 in the portion of the BHA above.
When fill (sand or other) is required to be removed from the wellbore, it is conducted by performing a “reverse cleanout”, meaning pumping fluid down the CT annulus and taking returns up the CT, in a reverse flow. The returns can also include the abrasive fluid used in the abrasive perforating process and, in the context of the present disclosure, this is considered to be included in reverse cleanout. A reverse cleanout flow for a BHA having a reverse ball check valve is shown in FIG. 2. During reverse cleanout the reverse ball check valve 70 allows fluid and fill from the wellbore to enter the nozzle 100 at the bottom of the BHA, enabling the fluid and fill to flow up to surface via the CT.
As shown in FIG. 3, in some BHAs, a double flapper check valve (DFCV) 12 is provided to regulate the flow direction, eliminating the usefulness of the reverse ball check valve 70. This is used, for example, in vertical high pressure wells. The DFCV 12, however, only allows fluid to flow in the CT in the conventional downward direction. If a cleanout is required with this BHA configuration for abrasive perforating, a completely separate BHA is needed on the end of the CT, or the current BHA needs to be brought to surface and modified, to remove the fill. FIG. 3 illustrates the two BHAs that are needed if the BHA has a DFCV 12. Therefore, to conduct abrasive perforating and cleanout using a BHA with a DFCV 12, the operator must alternate between using two completely separate apparatus, which results in significant time wastage and additional cycling fatigue of the CT.
Abrasive perforating has more recently also been adapted for horizontal wellbores. Different BHA configurations require different methods of abrasive perforating depending on wellbore conditions.
One method of abrasive perforating of a horizontal wellbore is by using the same method as typically used in vertical wells, using a BHA with a reverse ball check valve. This method has a risk of creating a “wormhole” in front of the BHA while conducting reverse cleanout, wherein reverse cleanout is only effective around the end of the BHA, resulting in a hole barely larger than the BHA and therefore the BHA eventually becoming stuck in the well. The reason this risk is more present in a horizontal wellbore than in a vertical wellbore is that, in the vertical wellbore, the fill will typically keep falling to the end (bottom) of the BHA by force of gravity and the annular flow velocity, enabling the fill to enter the BHA and travel up the CT for removal from the wellbore. However, in a horizontal wellbore, gravity does not bring the fill to the end of the BHA, so the only means of transporting the fill to the end of the BHA is by the annular flow of the cleanout medium from surface to the BHA end. Depending on the size of the wellbore and cleanout medium, the annular velocity may not be high enough to sweep the entire fill to the end of the BHA.
Another method that has been used for abrasive perforating of a horizontal wellbore is replacing the reverse ball check valve 70 with a one-way valve 72 having a ball seat 92 and a corresponding control ball 90, as shown in FIG. 4. A control ball 90 of corresponding size to the ball seat 92 is placed on the ball seat 92, either by manual placement while the BHA is at the surface of the worksite or by circulating the ball down the CT using fluid. When operating the BHA in the conventional forward direction, the ball 90 is urged against the ball seat 92, creating a seal and directing the flow through the jetting nozzle(s) 50, just as the reverse ball check would have done. The difference is that, with a ball 90 and ball seat 92, reverse circulation is only used to remove the ball 90 from the BHA, and not to remove fill from the wellbore. Once the ball 90 has been removed from the BHA and is caught at the surface of the worksite, pumping is again switched to the convention direction, taking returns of fill up the CT annulus for a cleanout of the fill from the wellbore. Similar to the case of a reverse ball check valve 70, two directions of flow in the BHA are required. Therefore, a DFCV cannot be used in this method. Furthermore, a BHA using a ball seat 92 and corresponding control ball 90 typically requires a more elaborate rig-up of treating iron that includes a ball catching/launching assembly.
Another existing method being used for horizontal wellbores uses a more lengthy approach using DFCV 12 when the well conditions so require (e.g. high pressure/operational procedures/result of risk assessment). This method, just as the case when a DFCV 12 is required in a vertical wellbore, requires two different BHA assemblies for perforating and cleanout. A cleanout can be performed before abrasive perforating when limited to one direction of flow in the CT (e.g. DFCV 12 present in the BHA) if a ball seat 92 is used below the cutting sub 40 containing the jetting nozzle(s) 50 in the BHA and the ball 90 is left out of the BHA when at surface. The cleanout is done then the ball 90 is circulated down to the ball seat 92 via the CT and seals off the lower section of the BHA. In this case, the process cannot be reversed and the BHA will now remain in abrasive perforating mode so if another cleanout is required the BHA will need to be brought to surface to have the ball 90 removed.
Other methods of abrasive perforating and fracturing have recently been developed which utilize a multi-set bridge plug (isolation and anchor assembly). Referring to FIG. 5, shown is another prior art BHA system which is similar to that shown in FIG. 1, except that it includes a circulating/equalizing valve component 110, a resettable bridge plug 120, and a mechanical casing collar locator (MCCL) 130.
Using the system shown, a method is to run the BHA in hole, locate casing collars with the MCCL 130 to correlate depth if the BHA is equipped with a MCCL 130, position on depth, reciprocate the BHA to set the packer, establish circulation down the coiled tubing at the calculated perforating rates, pump fluid containing an abrasive medium, such as sand, through the jetting nozzle(s) to abrasive perforate the casing and formation, displace the abrasive slurry up hole or out of the well and execute the fracture treatment down the CT annulus. After the frac treatment a straight pull on the tubing opens an equalizing valve and unsets the packer. Then the tools are pulled up hole to the next interval to be treated and the BHA is cycled with mechanical movement back into setting position to set the tools at the next stage (depth to be perforated and fractured). At this time the BHA can be pressure tested to ensure the packer has a good seal and the process is repeated.
Another prior art method is to utilize the same primary BHA components as shown in FIG. 5 with the exception of a sliding sleeve locator in the place of the MCCL. That is, in addition to a specialized BHA, the system also consists of sliding sleeves, which are inserted in the casing string when completing a well wherever a frac is planned. To gain communication to the formation for the frac treatment the sliding sleeve is opened by the running string (BHA and CT) by setting the multi-set bridge plug inside the sleeve and then moving in hole to shift the sleeve down and open. The anchors on the bridge plug provide the means of transferring the force to the sliding sleeve for shifting it. As a contingency measure, at least one abrasive perforating nozzle is included in the BHA so perforations can be made for communication to the reservoir in the event a sliding sleeve will fail to open or if the wellbore is to be perforated (and possibly fractured) in an area a sliding sleeve was not placed when running the casing in the early stages of the well. During the frac treatment, with both of these systems, sand laden fluid is being pumped down the CT annulus and there is a potential for the sand to settle on top of the bridge plug and may cause a “stuck in hole” situation. In some instances a “screen out” can occur during a frac job, which is when the maximum pumping pressure is reached and an unplanned amount of sand laden fluid is in the wellbore and is not able to be displaced into the formation. This has a high potential for causing the BHA to become stuck in the hole. In this case, with the current two systems the contingency would most likely be to commence pumping down the CT and through the BHA with fluid exiting the abrasive jetting nozzle(s) to circulate the sand/sand laden fluid out of the annulus and off of the BHA in the conventional direction. Because of the high pressure drop of the abrasive jetting nozzle(s) flowrate down the CT, and consequently annular velocities required to remove sand, will be lower than they would be without the high back pressure. There is the ability to reverse circulate (down the annulus/up the CT) because of the ball and seat in circulating/equalizing valve, but when sand concentration in the annulus is high this is not a good option due to the high risk of plugging of the CT if this high concentration sand laden fluid enters the CT.
Each of the prior art methods of abrasive perforating, whether in vertical or horizontal wellbores, requires either reversing circulation, use of two assemblies or removal of the BHA to the surface when a cleanout is required following abrasive perforating. All of these options are time consuming and in some cases not an option such as when a frac treatment screens out while using the prior art system of FIG. 5 and becoming stuck in hole is a risk and high rate forward circulation is the only way to get the fill removed and free the BHA. What is required, therefore, is a means for abrasive perforating in which a single assembly can be used in a single flow direction for both abrasive perforating and cleanout and which can be controlled without removing the BHA from the wellbore.